We hear a lot about Hawaii’s Renewable Portfolio Standard (RPS) which requires 100% of the utilities’ net electricity sales to come from renewable sources by 2045. Subsidies, rapidly declining solar panel costs, and high electricity prices have led to the proliferation of distributed rooftop solar photovoltaic (PV). By the end of 2016, roughly 1 out of 7 occupied housing units on Oahu had a solar PV system (City and County of Honolulu, 2017; ACS, 2017). Integrating increasing amounts of intermittent renewable energy, including utility-scale solar and wind, presents a challenge for electricity grid operators since at any moment supply must equal demand. While it is easy to get wrapped up in how to enable more cost-effective renewable energy on an outdated grid, designed for centralized generation and a one-way flow of electricity, I’d like to step back for a moment and remind ourselves of the rationale for renewable energy policies to ensure we meet our policy objectives and, towards that end, are using the appropriate policy instruments.

Like the U.S., Hawaii relies heavily on fossil fuels to meet its electricity needs (see Figure 1 for Hawaii’s generation mix in 2016).1 Since fossil fuels are a depletable resource, the transition to renewable energy is theoretically inevitable absent any policy intervention. It is the speed of transition that is inefficient from a social perspective due to the presence of environmental externalities (Gillingham and Sweeney, 2010).2 The damages from greenhouse gas (GHG) emissions are spillover costs not reflected in current market prices for fossil fuels. As a result, there is both more fossil fuel consumption than socially optimal and the transition time to renewable energy is slower. Basic economics tells us that the best way to mitigate climate change is to “get prices right” by imposing a tax equal to the marginal damage cost of emissions or apply emissions trading.3 Such market-based incentives are less costly and allow for more flexibility than traditional command-and-control policies in which uniform standards (ambient, emissions, or technology) must be met by affected sources. The marginal damage cost of GHG emissions can be given by the "social cost" of carbon—the per unit present value of the total damages from carbon dioxide (CO2) emissions or alternatively the benefit from emissions abatement.

Instead of a broad carbon tax, most of the focus in Hawaii has been on taxing the barrel of oil. This of course also discourages fossil fuel use; however, the barrel tax we have is quite modest so its major impact is as a source of funding. As only $1.05 per barrel is levied—and this excludes aviation fuel and fuel sold to a refiner—it does not capture the full externality cost. And the dirtiest fuel, coal, is also currently exempted.4 We also rely on policy instruments like the RPS or subsidies for renewable energy, which though they likely reduce carbon, not necessarily at least-cost.5 These policies were not founded on the basis of environmental impacts (namely climate change), but instead were primarily driven by affordability6 and a stronger local economy.7

To address climate change specifically, we have a separate policy, Act 234 (2007), which requires Hawaii to reduce its GHG emissions to 1990 levels by 2020. The statewide GHG limit is 13.66 million metric tons of carbon dioxide equivalent (MMTCO2e), excluding air transportation and international bunker fuel emissions and including carbon sinks. In response, GHG rules were established for the electricity sector in 2014; facilities emitting over 100,000 tons of CO2e per year (excluding municipal waste combustion operations and municipal solid waste landfills) are required to reduce emissions by 16% from 2010 levels in 2020. Partnering across the 20 affected facilities is allowed to achieve cost-effective emissions reduction.

Figure 2 shows Hawaii’s 1990 and 2007 GHG emissions inventory—the most recent inventory to date.8 It shows that the electricity sector produces approximately 30% of GHG emissions. Other sectors matter too, especially transportation. By focusing on economy-wide GHG emissions reduction, coupled with the appropriate policy instrument to meet the policy objective, not only will it encourage more renewable energy in the electricity sector, but it will also facilitate coordinated efforts in other sectors. For instance, ground transportation comprises many individual actors, which together account for 14-18% of emissions. It is also the fastest growing sector (38% increase between 1990 and 2007). Emissions from ground transportation have likely continued to increase despite increased fuel efficiency and the growth of electric vehicles (EVs) in recent years.9 This suggests that even if the electricity sector were to comply with or exceed the 16% reduction, the growth of ground transportation likely outpaces the decline in the electricity sector; without coordinated state action we may not meet Act 234.10

Climate change policy offers a potentially economy-wide approach that can align multiple policy goals—whether it is more affordable, locally produced electricity or the electrification of transportation. An economy-wide carbon tax also means that the same $/ton cost would be levied on gasoline. While there is a federal gasoline tax of 18.4 cents/gallon and a state gasoline tax of 16 cents/gallon (EIA, 2017), this does not necessarily amount to the full externality cost of pollution.11 With the proper price signals, getting more EVs on the road will happen without any other overarching goals or mandates in the transportation sector. Whereas federal Corporate Average Fuel Economy (CAFE) standards increase the fuel efficiency of new vehicles, they do not encourage people to drive less. A carbon tax would target both vehicle purchase and driving decisions for new and used vehicles. Moreover, a carbon tax offers the opportunity to address distributional impacts. Carbon taxes are perceived to be regressive because fuel comprises a greater share of spending for low-income households. However, mandates are more regressive than a revenue-neutral carbon tax which can redistribute revenues to taxpayers by cutting other taxes (e.g. payroll, personal income, and corporate taxes) or through direct payments (flat “check in the mail”).12

Lastly, a carbon tax would also address flaws in today’s current energy policies. For instance, the 100% RPS, as currently calculated, does not translate into Hawaii generating all its electricity from renewable sources since distributed rooftop PV is counted in the numerator (renewable generation) but not in the denominator (total electricity sales). As calculated, only electric utilities are subject to the law. The gas utility and other large commercial customers who install their own generators are not part of the picture, perhaps prompting large customers to switch to gas or defect from the grid entirely. Instead of devising an amended metric to close such loopholes,13 stronger GHG policy—a carbon tax to either complement or replace the RPS—would align statewide goals and avoid the consequences of any “leakage” across sectors.

A carbon tax could also help to make good on the goals of Hawaii’s energy efficiency portfolio standards (EEPS). In contrast to an RPS which targets the supply-side, the EEPS focuses on electricity consumption, calling for a 30% reduction by 2030, equivalent to 4,300 gigawatt hours based on a 2008 baseline forecast of electricity consumption in 2030. Measuring progress according to the design of the standard is extremely difficult without a “counterfactual”—that is, electricity consumption absent any energy efficiency savings. In addition, similar to CAFE standards in the transportation sector, some efficiency gains are offset by increased consumption (a rebound effect). There are also many individual actors, some regulated by the Public Utilities Commission, and others, unregulated. An economy-wide carbon tax would incent fossil fuel conservation by all. Note also the volumetric surcharge design to support energy efficiency programs currently presents regressive impacts.14

There’s a lot of background activity around compliance with Act 234 on the horizon with affected facilities submitting their updated emissions reductions plan and the DOH updating and developing GHG inventories and projections. As we move forward, we should consider not only working towards compliance in one year but in perpetuity. This blog post has highlighted the critical link between our broader energy goals and how climate change policy and its policy instruments can enable us to reach those objectives. Maybe Act 32 (2017), which commits Hawaii to meeting some of the principles and goals laid out in the Paris Accord, will be a way to keep us on track. But without any specifics as to how we are to achieve such reductions—through a carbon tax or otherwise—it is largely symbolic. It’s time for a comeback in energy and GHG policymaking.

UHERO BLOGS ARE CIRCULATED TO STIMULATE DISCUSSION AND CRITICAL COMMENT. THE VIEWS EXPRESSED ARE THOSE OF THE INDIVIDUAL AUTHORS.

1Though the composition of fossil fuels differs; in the U.S., natural gas and coal comprise roughly 30% each and nuclear, 20% in 2016 (EIA, 2017).

2Yet with technological advances and the discovery of new reserves, it could also be argued that the supply of fossil fuels are “nearly limitless.” In either case, without correcting for the market failure, the transition would be to slow to mitigate the impacts of climate change (Covert et al., 2016).

5Emissions reduction depends on the generation source displaced and on increased consumption due to reduced prices. Murray et al. (2014) show tax credits have a small impact on GHG emissions, and in some cases, emissions increase. Palmer and Burtraw (2005) show that neither a production tax credit or an RPS leads to as high of and as cost-effective a reduction as a cap-and-trade program.

13In the 2017 legislative session, the Department of Business Economic Development and Tourism (DBEDT) for the second time, proposed to amend the RPS calculation to correct for this error (see SB906, HB1040).

14As a per kWh charge, customers who are able to reduce or offset their energy use through energy efficiency and distributed PV pay a lower dollar amount than customers who do not have access to such technology. The expansion of distributed PV puts a greater burden on these (generally) lower-income customers.

Electric vehicles (EVs) can be a cleaner means of transportation compared to cars with traditional gasoline engines. They have the added benefit of being able to provide support to the electric power grid—an increasingly important attribute in states like Hawaii with high levels of intermittent renewable energy. To achieve widespread deployment of EVs, we need to know why consumers choose to buy an EV rather than a traditional car. Towards this end, we have conducted two studies that evaluate the effects of state-level policy incentives in the United States and that estimate “spillover effects” from geographic peers in Hawaii who purchase EVs. Preliminary results are presented below.

State EV Policies

Though EV battery costs have fallen rapidly in the last several years, the upfront cost of EVs still remain a barrier to rapid adoption. States have implemented a range of policies to encourage consumers to purchase EVs—financial and otherwise—but it is unclear how effective these policies are at achieving additional EV uptake. We estimate the effect of policy on EV adoption using semi-annual new vehicle registrations by EV model from 2010 to 2015 and a rich dataset of consumer-oriented state-level policies designed to promote EV purchases. We focus our policy analysis on EV vehicle purchase incentives and a range of other policies like home charge subsidies, reduced vehicle license taxes or registration fees, time-of-use rates, emissions inspection exemptions, high occupancy vehicle lane exemptions, designated and free parking, and an annual EV fee (that discourages EV purchase). As a rough indicator capturing the overall number of policies that states have used to incentivize consumer EV adoption, we add the number of policies up by state, illustrated in Figure 1. We separate the “policy index” (ranging from 0 to 9) by battery electric vehicles (BEVs) and plug-in hybrid electric vehicles (PHEVs) and show how it has changed over time (as shown in Figure 1 for the second half of 2011, 2013, 2015). Overall, there are more BEV policies, where California and Arizona are leaders in the number of EV policies adopted.

Figure 1. State Policy Index: BEVs (top) and PHEVs (bottom)

Our econometric estimates show that state policies positively impact EV adoption for both BEVs and PHEVs. The vehicle purchase incentive has a pronounced effect on BEV uptake. A $1,000 increase in the purchase incentive leads to an approximately 15% increase in sales of BEVs. We test these results by examining states that have ended large purchase subsidies, and find that BEV adoption declines. Other policies—aggregated together into a policy index—likewise increase EV uptake, though more so for PHEVs. This suggests that policies related to usage are perhaps more relevant for PHEVs. Each additional policy increases PHEV sales by 18%. The contrast between the effectiveness of different types of incentives for BEVs and PHEVs offers some guidance for policymakers evaluating current state policies or considering adopting new state EV policies. In sum, we find that state policies have driven additional EV uptake—extending EV purchases to consumers who would not have otherwise entered the market.

Geographic Peer Effects for Teslas

We also examine the role of geographic peers in EV uptake in Hawaii. Hawaii provides an excellent case for studying peer effects because it has strong EV adoption, the second highest amongst U.S. states in EVs per capita (IHS Markit, U.S. Census Bureau, 2010 – 2015). Although federal and state governments offer a variety of consumer incentives, the decision to adopt EVs may also extend beyond economic and policy motivations to include behavioral and social components. Social networks, also called “peer effects,” could have a potentially large influence on vehicle choice if people are influenced in their decision to adopt an EV by peer decisions to adopt EVs. Our second study examines peer effects defined by geographic networks, i.e., by visual observations of EVs registered in one’s neighborhood. Using zip code-level EV registration data from 2013-2016 for Hawaii, we exploit a three-month gap between adoption decisions and deliveries of Teslas to estimate presence and size of peer effects. Tesla EVs were important for reigniting interest in EVs more generally and amount to 13% of registered EVs on Maui, Oahu, and Hawaii Island. Our econometric analysis identifies statistically significant neighborhood effects. Figures 2 and 3 illustrate EV and Tesla uptake, respectively, by zipcode on Oahu, Maui, and Hawaii Island; Kauai is omitted due to data limitations.

Figure 2. EV Adoption on Oahu, Maui and Hawaii Island

Figure 3. Tesla Adoption on Oahu, Maui and Hawaii Island

We find that geographic-based peer effects generate one additional Tesla sale for every 26 Teslas sold in a zip code. How meaningful the magnitude of these peer effects may be is likely contextual. If for example policy focused specifically on marketing to peers and social networks, this may not provide much gain. However, as a pure spillover effect, peer effects can be meaningful. If, for example, Hawaii were to offer a second round of vehicle purchase subsidies, the peer multiplier effect estimated in our analysis would increase the additional Teslas purchased by 4-5% over each year of the vehicle’s life. As a lower bound, this amounts to roughly 1 additional Tesla per zipcode as a result of peer effects. One note of caution: whether the peer multiplier for Teslas—a very high-end vehicle—will translate as the peer multiplier for other lower-priced EVs, such as the Nissan Leaf or Chevy Volt, remains an open question.

UHERO’s Energy Planning and Policy Group has been writing about how variable pricing of electricity, both wholesale and retail, can lower the cost of intermittent renewables. Get the rates right, and facilitate easy open-access to the grid for both buyers and sellers, and amazing things can happen. The idea is that variable rates will encourage households and businesses to shift electricity demand toward intermittent supply, and facilitate creative, low-cost storage of power, all of which would enable cheaper, faster growth of renewables.

Hawaiian Electric Industries (HEI) seems to be moving in this direction. With the right incentives they might move quicker. Unfortunately, the utility has little incentive to implement variable pricing, except to please the Public Utilities Commission (PUC), since these adjustments might do for free what otherwise requires investment in batteries, new power plants and other grid upgrades. Under current regulations HEI grows its profits by maximizing investment, regardless of whether or not those investments are cost effective.

But here I’d like to focus on another rate that can make a big difference in the cost of renewable energy: the interest rate used to finance capital investment. It’s a good time to write about this little detail as the PUC, Consumer Advocate, legislators and others pour over HEI’s latest, more comprehensive revision of the Power Supply Improvement Plan, or PSIP. While there’s lots to study and think about here—all 1200 pages of it—the interest rate assumptions strike me as, well, high. And I wonder if these could be a key factor underlying some differences between HEI’s plan and our own Matthias Fripp’s plan. The plan also includes off-shore wind, which at a cost of about $4/Watt, may be an economic part of the portfolio—it will be good to incorporate this possibility into Fripp’s planning model.

Here’s the crux: interest rates have been trending down for the last 35 years, and sit near all time lows today. And there’s little hint in market data that they’re likely to go up much soon. Yet, in the midst of these low rates, HEI’s new PSIP uses rates that were typical for utilities some 20 years ago.

HEI’s assumed cost of capital is comprised of 57% equity, for which they claim a cost of 11%, which exceeds rates that many public utility commissions complained about as early as 2004, when market interest rates were much higher than they are today. Expectations for future rates of return on equities are smaller today than they were ten or twenty years ago, and utilities tend to have lower-than-average rates of return because they are considered safe, since returns are all-but-guaranteed by the government. Rates for debt also appear roughly 20 years old. Today, typical rates on corporate “a” bonds, a conservative rating for utility investments, are less than 3 percent on average, and barely over 4% for long-term issues. HEI assumes 7% for long-term debt, which is assumed to comprise 39% of capital costs. The return rate for equity is a policy decision, but it stands to reason that rates ought to follow market rates, which have come down 3-4 percent since 10% was typical.

Clearly, higher overall interest rates would imply higher overall generation costs and higher rates for customers. But the rate also influences the cost-effectiveness of different generation mixes. For wind and solar, nearly all costs are for up-front capital. Conversely, for traditional power generation (oil, coal, natural gas and biofuels), fuel and operation costs generally comprise a larger share of cost than generating equipment. Higher rates therefore favor traditional generation.

Another more subtle consideration is that solar and wind investments have lower risk premiums than traditional fuel-based generation. The reason is that solar and wind pay a higher dividend if fuel prices spike, which is just the opposite of traditional fuel-based generation. This means solar and wind can do more to reduce risk from the larger investment portfolios of typical equity shareholders, and should therefore have a somewhat lower cost of capital.

The upshot of all this is that the high rates used in the PSIP artificially make natural gas and biofuels more attractive from a cost perspective than solar or wind, and generally cause the projected path of customer rates to be higher than they need to be. Two or three percentage points can make a really big difference, as any homeowner with a mortgage can tell you. You can also get a sense of the magnitudes by playing with our solar calculator (now mostly obsolete due to the end of net metering).

We shouldn’t blame HEI for doing what they can to negotiate rates up, for the rate on equity, and the share of capital they finance with equity, is their main channel for growing profits. HEI has a legal obligation to its shareholders to seek to maximize profits, which the new PSIP does skillfully. It’s even better for them if higher rates causes capital investments better-suited to HEI (like developing a new traditional power plant, or retrofitting an old one) to be more attractive than those best suited to a third-party provider. And making the rate for debt similarly high may help to obscure the fact that the equity rate is so high. The problem with cost-of-capital rates falling much less than market interest rates is not unique to Hawaii, although the PSIP rates still appear higher than typical.

As I’ve argued earlier, regulatory incentives could be changed such that HEI would have an incentive to find the most inexpensive and cost-appropriate capital possible and implement variable rates. This could also help HEI align its profit-oriented goals with the state’s affordable, renewable energy goals. The trick is to divorce their profits from the size of their own capital investments, and instead link profits to improvements in overall cost efficiency of the system, including distributed energy. Other states are also flirting with different incentives for utilities. Finally, build renewable energy goals directly into the cost structure by taxing fossil fuels and/or subsidizing renewables, regardless of source. This approach is one option for a “new business model” that many vaguely refer to.

Other models could work too. I gather that many see these high rates and conclude that a government municipality or cooperative, which would have considerably lower capital costs, as the answer. But it’s important to keep in mind that these alternative structures have incentive problems too. Another option would be to replace HEI with an Independent Service Operator, or ISO. I’m still learning sbout ISOs, but think the model could hold a lot of promise for Hawaii. I’ll have more on ISOs in another post.

Today’s low interest rates, combined with remarkable technological advance in renewable energy, creates what could be an amazing opportunity for Hawaii. It’s conceivable to me that we could transition toward 100% renewable faster than many currently believe. Maybe not in Dinah Washington’s 24 little hours, but soon enough. But to do it, and do it cost effectively, means getting the rates right.

Perhaps the greatest obstacle to a renewable-energy future is that our utility, Hawaiian Electric Industries (HEI), has little or no incentive to transform its operation into a model more suited for renewable energy. While there has been a lot of hand-wringing and criticism of HEI for its monopoly and slow approval of distributed solar, it’s important to realize the truly unprecedented change they are being forced to undertake. And worse, the new cutting-edge system they are being asked to adopt will literally undermine its profits.

Revenue decoupling (PDF) was supposed to correct HEI’s incentives by ensuring that the utility could recover the same revenue toward its operation costs even if they generated less electricity due to growth of distributed solar or improvements in energy efficiency, both of which have factored into higher electricity prices.

Revenue decoupling does make HEI less vulnerable to improved efficiency and growth of renewable energy over the short run. But over the long run the utility profits mainly from making new capital investments. For such investments they receive a nearly guaranteed rate of return that far exceeds low-risk borrowing costs. If the utility is forced to retire its old power plants and instead buy renewable energy from independent providers—the apparent inclination of the Public Utilities Commission---its rate base and profitability decline. Thus, even under revenue decoupling, low-cost renewables do not accord with HEI’s interests.

The larger problem is that the regulatory infrastructure is not conducive to a rapidly changing energy landscape in need of innovative and perhaps distributed solutions. HEI has little incentive to control costs, much less increase renewable energy in a cost effective manner.

It doesn’t need to be this way. We can fix regulatory incentives. But given the novelty of the renewable energy system we are creating, combined with Hawai`i’s geographic uniqueness, it seems unlikely that we can simply borrow a regulatory model from the mainland. Some are calling for our private utility to be replaced by publicly-run municipality, or possibly a cooperative like the one on Kaua`i. These models might work. But it’s not clear how long it would take to transition to these systems, or whether they will bring about the most innovative solutions.

What’s the fix? First, the utility needs to have some skin in the game. Full cost recovery via rate adjustments—the current regulatory situation---gives the utility virtually no incentive to be strategic in its management and planning. Instead, if costs fall due to cost-effective development or contracting of renewables, the utility should get to keep a share of the gains. The utility’s profits ought to be tied to its cost effectiveness, not the size of the capital outlay. At the same time, if oil prices rise, then the utility should absorb a share of the cost increases, such that it cares about oil price volatility just as its customers do.

Second, to the extent that the state wishes to favor renewables over fossil fuels, fossil fuels should be explicitly taxed and renewables subsidized. Such incentives could be made roughly revenue neutral and would be more effective at achieving renewable energy goals in a cost-effective manner than the state’s expensive and seemingly pointless renewable energy tax credits. Federal credits are more-than-adequate to make distributed generation cost-effective to homeowners, even under revised rate structures. And we should allow utility-scale and distributed renewable energy generation to compete on equal footing. Instead of the tax credit, customers should be able to sell all surplus generation to the grid at appropriate real-time rates.

Of course, regulators will need to negotiate a baseline profit level, how the baseline will change over time, the share of overall cost changes born by the utility and passed on to customers, and whether the utility’s share of cost improvements ought to phase out over a number of years. Regardless of these choices, these kinds of changes in regulatory structure would align the utility’s interests with their customers as well as the state’s renewable energy goals.

The big, encouraging news is that the cost of reducing greenhouse gas emissions and slowing global warming now looks cheap. While Hawai`i’s contribution to this global problem is minimal, if we can show the world how to do renewable energy in a smart, cost-effective manner, we could be a true global leader in helping to solve it. But without smart policy, we’ll only serve the interests of denialists and naysayers who will point to Hawai`i’s renewable energy boondoggle as an excuse for inaction.

HECO has recently proposed new time-of-use rates and is developing pricing for various kinds of demand response programs.The proposed programs are a long ways from the open-access, marginal-cost pricing, but they are a big step in the right direction.

The new time-of-use rates embody high-powered incentives for shifting loads to different times of the day (Table 1).Depending on an individual household’s use profile, many should be able to reduce their bills even if they don’t change the way they use electricity.Alternatively, some households might be tempted to install batteries, charging with solar or cheaper electricity during the daytime and discharging during nighttime peaks.Such strategies should be economical given these price differentials.

Unfortunately, these rates only apply to residential customers, which is a small share of the load (about 27%).To maximize load shifting potential and make use of real time meters already in place, we should quickly introduce variable prices for commercial-scale customers.

While time-of-use pricing is a step forward, the proposed time-of-use prices, despite their apparent 4-digit precision, do not reflect the true incremental cost of electricity.The true cost can vary significantly across hours in each block in the table of proposed rates, and across different days and seasons of the year.Expensive peak loads, for example, fall off sharply by 9pm, but peak-load pricing extends until midnight.Also, the difference between peak pricing and midday pricing far exceeds the current cost of serving these loads.Values are likely to change rapidly as the generation mix shifts increasingly toward renewables, so it appears that proposed prices anticipate future changes in generation. While the incentives are strong enough to kick-start demand response programs, it’s hard for customers to know how the rate structures will change over time.The uncertainty could discourage entrepreneurs looking to Hawai`i as a place to test their demand response technologies.

Over time, variable pricing could be improved in a number of ways.First, it is important to make the price-setting mechanism clear and transparent, so that customers and entrepreneurs developing smart devices can reasonably anticipate how prices will change going forward.The guiding mechanism should link to the overall system’s marginal cost of electricity.Second, customers should be given more choices.Some may prefer time-of-use pricing with the proposed simple three-block structure; others might embrace full-fledged real time pricing; others may prefer something in-between.As long as rates reflect typical costs in each block, customers will be free to choose a level of flexibility they are comfortable with.

How much will the new rates shift loads away from the peak and toward midday and early morning?The reality is that it’s very hard to know.In fact, it will still be difficult to know even after new rates have been implemented.Many households could probably select time-of-use pricing and save money without shifting loads at all.We won’t be able to tell whether they always tended to use electricity during the low-cost times or changed behavior as a result of time-of-use pricing.To know, it is important to observe real-time electricity use before and after the rate change. And we would further need to rule out the possibility that other factors besides the rate change were affecting use.

To accurately measure how much demand-response bang for the time-of-use buck the system is getting from variable rates, or any other change in policy, we need to run actual experiments.The idea is to offer up different pricing menus to different households and businesses for a trial run of a year or two.The pricing menus would need to be randomly assigned across customers, in part for fairness, but also to ensure that observed changes are not a reflection of selection bias.Some households might obtain opportunities to install smart devices that aid automatic shifting of loads. Some randomly selected customers would be reserved as controls, without the opportunity to choose a variable pricing contract.Such experiments could measure the actual and potential demand response much more precisely than simply changing policy for everyone all at once.

Of course, the public would need to be let in on the whole policy experiment. And it would further help to have some guidelines for how policy will evolve based on the outcomes of the experiments.There are a number of successful examples of such experiments, some of which show great potential for curbing peak loads, and customers that are happy participating in the program.While we can learn from policy experiments elsewhere, the load shifting needed in Hawai`i is different and more substantial.We need our own, thoughtfully-designed experiments to learn the true potential for demand response.